Single horizontal well thermal recovery process

ABSTRACT

The present disclosure describes a method for the recovery of hydrocarbons using a single horizontal well having both injection and production means. The well has a means for increasing fluid flow resistance in the wellbore. The injection and production means are operated so as to increase the fluid flow into the reservoir and reduce the fluid flow in the well. The means to increase fluid flow includes a constriction in the wellbore between the injection and production means, flow conditioners placed along a portion of the well between the injection and production means, and sealing elements placed in the well between the injection and production means. The production and injection openings are also positioned relative to the flow conditioners and sealing elements.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority of U.S. ProvisionalPatent Application No. 61/894,809, entitled “SINGLE HORIZONTAL WELLTHERMAL RECOVERY PROCESS” filed Oct. 23, 2013, which is herebyincorporated by reference in its entirety.

FIELD

The present disclosure relates generally to oil recovery processes andparticularly to thermal recovery and thermal/solvent recovery processesthat may be applied in viscous hydrocarbon reservoirs, and specificallyin oil sands reservoirs. More specifically, the disclosure describes theuse of a single horizontal well for injection and production in thermaland/or solvent recovery processes.

BACKGROUND

Among the deeper, non-minable deposits of hydrocarbons throughout theworld are extensive accumulations of viscous hydrocarbons. In someinstances, the viscosity of these hydrocarbons, while elevated, is stillsufficiently low to permit their flow or displacement without the needfor extraordinary means, such as the introduction of heat or solvents.In other instances, such as in Canada's bitumen-containing oil sands,the hydrocarbon accumulations are so viscous as to be practicallyimmobile at native reservoir conditions. As a result, external means,such as the introduction of heat or solvents, or both, are required tomobilize the resident bitumen and subsequently harvest it.

A number of different techniques have been used to recover thesehydrocarbons. These techniques include steam flood, (i.e.,displacement), cyclic steam stimulation, steam assisted gravitydrainage, and in situ combustion, to name a few. These techniques usedifferent key mechanisms to produce hydrocarbons.

Commercially, the most successful recovery technique to date in Canada'soil sands is Steam Assisted Gravity Drainage (SAGD), which creates andthen takes advantage of a highly efficient fluid density segregation, orgravity drainage, mechanism in the reservoir to produce oil. Atraditional system which is a concomitant of the SAGD process is theSAGD well pair. It typically consists of two generally parallelhorizontal wells, with the injector vertically offset from and above theproducer.

SAGD was described by Roger Butler in his patent CA 1,130,201 issuedAug. 24, 1982 and assigned to Esso Resources Canada Limited. Since thattime, numerous other patents pertaining to aspects and variations ofSAGD have been issued. Also, many technical papers have been publishedon this topic.

The SAGD process, as embodied in the operation of a well pair, and asapplied in an oil sand, typically involves first establishingcommunication between the upper and lower horizontal wells. There areboth thermal and non-thermal techniques for establishing this inter-wellcommunication. Subsequently, steam is injected into the overlyinghorizontal well on an ongoing basis. Due to density difference, thesteam tends to rise and heat the oil sand, and thereby mobilizes theresident bitumen. The mobilized bitumen is denser than the steam, andtends to move downward towards the underlying horizontal well from whichit is produced. By operating the injector and the producer underappropriately governed conditions, it is possible to use the densitydifference to counteract the tendency of more mobile fluids to channelor finger through the less mobile fluids and overwhelm the producingwell. Thus, in traditional SAGD operations, each well in the well pairhas a specific and distinctive role in ensuring that the efficiencieswhich can be achieved with a gravity-dominated process are realized.

Not long after the patenting of SAGD, various investigators began toexamine the feasibility of operating a process which, like SAGD, isgravity-dominated, but which is operable with a single well rather thana well pair. The early concepts involved a single vertical well andrepresent a different configuration than that described in the presentdisclosure.

In U.S. Pat. No. 5,014,787 filed Aug. 16, 1989, Duerksen of Chevrondescribes a single vertical well system, with detailed focus on thetubing-casing-packer configuration within the wellbore. Packers areinstalled to confine and direct flow within the wellbore and tosegregate within the wellbore the injection and production intervals.This system utilizes a “drive fluid”. Generally drive fluids are used innon-SAGD systems to drive or “push” the hydrocarbons to a producer well.This is in contrast to recovery processes in which a gravity drainagemechanism is either dominant or operative. Duerksen's system andassociated method utilize a “drive fluid” to establish near-wellborecommunication within the reservoir between an upper set of injectionperforations and a lower set of production perforations and does notmention gravity drainage or a gravity-dominated process.

In U.S. Pat. No. 5,024,275 filed Dec. 8, 1989, to Anderson et al,assignee Chevron, a similar system is described as that in U.S. Pat. No.5,014,787 to Duerksen, but with somewhat modified vertical wellborehydraulics. Also, mention is made of maintaining a liquid level withinthe reservoir such that uncondensed fluids are not inadvertentlyproduced. However, as with U.S. Pat. No. 5,014,787, reference is made toa “drive fluid”. There is no mention of a recovery process whichincludes gravity drainage as an operative mechanism.

U.S. Pat. No. 5,238,066 filed Mar. 24, 1992 to Beattie et al., assigneeExxon, pertains to a method introduced in the later stages of cyclicsteam stimulation (CSS) operation, and involves alternating periods ofsteam injection into upper perforations in a vertical well followed byhydrocarbon production from lower perforations. There is no mention orimplication of a gravity-dominated recovery process or a process inwhich gravity drainage plays a role.

The paper titled “Lloydminster, Saskatchewan Vertical Well SAGD FieldTest Results”, published in the Journal of Canadian PetroleumTechnology, November 2010, Volume 49, No. 11, by Miller & Xiao of HuskyEnergy, describes a field experiment involving a single vertical wellSAGD-type operation. The reservoir in which the experiment was conductedinvolved viscous oil, but with considerably lower native viscosity(i.e., higher mobility) than the types of bitumen present in the oilsands. The authors indicated that the test “demonstrated that a singlevertical well SAGD configuration could be successfully completed andoperated”. For reasons that the authors attributed to geology andinitial fluid distribution within the reservoir setting, the authorsnoted that “Field performance of single vertical SAGD Well 4C11-1 wasnot as good as expected”, and suggested that single vertical well SAGDmethodology could be “used to help determine if sufficient verticalpermeability exists for the low-pressure gravity-based horizontal wellSAGD process to be successful”. That is, the authors proposed that theirsingle vertical well SAGD methodology could be applied as a diagnostictechnique for determining vertical permeability within the reservoirrather than as an effective recovery process.

Other vertical well configurations have been proposed. For example,X-Drain™, a trademarked and patented concept by GeoSierra/Halliburtoninvolves a single vertical well that employs a SAGD-type process.Emanating from the vertical well are a number of highly permeablevertical planes, similar to vertical hydraulic fractures, with thefractures propped or held open by a permeable propping agent. Each suchplane has its own azimuth so that the effect, when viewed from above, isgeometrically similar to a hub (the vertical well) and spokes (theinduced multi-azimuth vertical planes). Steam is injected into the upperportion of the well and moves outward through the highly permeablepropping agent contained within these multi-azimuth vertical planes tomobilize the bitumen at the faces of each plane.

For many decades, Imperial Oil has practiced a cyclic steam stimulationprocess at their Cold Lake oil sands operation using vertical andinclined wells. The viability of the recovery process depends on the useof formation fracturing during the injection cycle to create a largelyvertical fracture that spans a significant vertical portion of theformation. While this is a single-well process, the perforations orwellbore openings for injection are the same as those used forproduction. Thus, the recovery mechanism relies on a production flowpath that is fundamentally the same as, and indeed largely created by,the preceding injection flow path.

Canadian patent application CA 2,723,198 filed Nov. 30, 2010 to Shuxing,assignee ConocoPhillips, describes a vertical well recovery processwhich can include a gravity-dominated mechanism. The patent applicationdescribes a well configuration involving a single well with an upper anda lower set of openings or perforations. It further requires thecreation of two horizontal fractures—one opposite the upper injectioninterval and one opposite the lower producing interval. However, thereare additional costs and other disadvantages to fracturing so it may notbe feasible or desirable for a particular formation.

Because of their vertical well orientation, none of the foregoingsingle-well techniques enjoys the inherent advantage offered byhorizontally oriented wells, which can traverse and access a largeportion of reservoir. The obvious advantage of a horizontally orientedsingle well was recognized by various investigators, and concepts for asingle horizontal well recovery system and process were put forward.

One such approach is described in U.S. Pat. No. 5,167,280 to Sanchez etal, assignee Mobil, issued Dec. 1, 1992. This patent discusses thecirculation within the wellbore of a solvent which is capable ofrendering the viscous oil more mobile. A process is employed in whichthe pressure gradient and the fluid concentration gradient are opposed.That is, the pressure gradient is maintained so that flow is inward fromthe reservoir to the well. At the same time, the viscous oil reservoiris exposed to the solvent via diffusion. The aim is to obtainsimultaneous outward stimulation of the reservoir by the solvent andinward flow of mobilized viscous oil to the well. The practicality ofmaintaining the operating conditions necessary to achieve opposinggradients is highly questionable, as an inordinate degree of monitoringand control would be required.

Canadian Patent 2,162,741 to Nzekwu et al, assignee CNRL, and filed Dec.20, 2005, describes a single horizontal well recovery process thatincludes both gravity drainage and steam flooding. The patent describesa process whereby steam is directed to the distal end of the singlehorizontal well via insulated tubing, making its return toward theproximal end of the well in the annular region between tubing and linersuch that a portion of the returning steam migrates through the slottedliner into the reservoir and mobilizes oil. A problem with this type ofconfiguration is that the resistance to fluid flow along the path fromthe well into the reservoir is very much greater than the fluidresistance along the annulus between the outer surface of the tubing andthe inner surface of the liner. Accordingly, only a small portion of theoverall injected fluids will enter the reservoir and mobilize oil. In alow pressure operation mode, Nzekwu restricts the injection andproduction rates to such an extent that a liquid level builds in thevertical part of the primarily horizontal well, which hydrostaticallysupports the steam chamber pressure. That is, the liquid head is equalto the steam chamber pressure. There is a low pressure drop in theannulus from the distal end to the proximal end. Using this system, thelongitudinal growth of the steam chamber in the reservoir, i.e. from thetoe towards the heel, is promoted by the small pressure drop that existsalong the horizontal well and would be extremely slow and result in verylow production rates. In a high pressure mode, Nzekwu describes apreferred configuration in which a packer is placed near the distal endof the well to isolate the injection and production zones in an attemptto direct more of the steam into the reservoir. As described by Nzekwu,the packer is set over a blanked-off interval of the liner that isapproximately one metre in length. Thus the interval of isolation isextremely small relative to the length of a typical horizontal well, andthe ability of that isolation interval to cause a diversion of injectedfluids into the reservoir before they ultimately flow back into thewellbore will be very limited in space and time. That is, as some of thereservoir on the downstream side of the packer is heated, and thehydrocarbons mobilized and produced, the injected steam will enter thereservoir on the upstream side of the packer and exit the reservoirshortly thereafter on the downstream side of the packer, where it willre-enter the wellbore and flow to the proximal end with little or nofurther effect in mobilizing oil.

A paper by Elliot and Kovscek prepared for the U.S. Department ofEnergy, dated June 2001, and titled “A Numerical Analysis of Single-WellSteam Assisted Gravity Drainage (SW-SAGD) Process” describes simulationscarried out in which the horizontal well is subdivided into two equallengths, with the injection interval occupying the distal half and theproduction interval occupying the proximal half of the wellbore length.The distal and proximal segments can be demarcated within the wellboreby a single intervening packer, or packer assembly, and open intervalsfor injection and production are separated from each other by a distanceof 30 metres. Relative to the 800 metre length of the well representedin their simulations, which is a typical length for a SAGD well, this isa very small separation interval, so that fluids injected into thereservoir on the upstream side of the packer will short-circuit backinto the wellbore after a relatively short traverse within thereservoir. However, the authors comment that while their work involvedmaintaining this equal-length configuration, it is not necessary to doso. The authors also limit the effectiveness of their method by notingthat “application of SWSAGD to exceptionally viscous oils will bedifficult”. The authors suggest an upper limit of 10 Pa-s. This is incontrast to the invention to be described herein, which includesdevices, well configurations and techniques that promote or maximizeexposure of the reservoir to mobilizing fluids. A further contrastbetween the present invention and that of Elliot and Kovscek is theapplicability of the present invention in oil sands where the nativebitumen may be 100 times more viscous than the limit set by Elliot andKovscek on the applicability of their method.

A paper by Marin et al of PDVSA, presented at the World Heavy OilCongress in Edmonton Alberta in 2008 (Paper 2008-348), and titled“SW-SAGD Pilot Project in the Well MFB-617, TL Sands, MFB-15 Reservoir,Bare Field, Eastern Basin of Venezuela” discloses a single horizontalwell configuration for SAGD operation. The wellbore contains twostrings—one for injection and the other for production. However, whilethe injection string traverses the length of the horizontal wellbore,the production string is confined to the vertical portion of thewellbore. FIG. 4 of the paper clearly illustrates the verticality of theproduction tubing and this is re-enforced within the text whichdescribes the tubing as having been set 650 ft. above the top of thereservoir.

This same well (MFB-617) is the subject of a paper by Mago et al ofPDVSA, presented at the World Heavy Oil Congress in Aberdeen Scotland in2012 (Paper 2012-348). There are no indicated completion changes for thewell, so that the basic configuration teaches away from that taught inthe present disclosure. However, the authors conducted simulationstudies involving alternative configurations for steam injection. Inthose simulations, steam is injected along a horizontal well thatinvolve configurations with one, two and three steam injection pointsalong the length of the well. However, there are no teachings in thispaper that pertain to management of the resistances to flow as is thecase with the present disclosure.

Canadian Patent 2,752,059 to Kjorholt, assignee Statoil, describes asingle horizontal well whose wellbore contains a production conduit andan injection conduit, with openings in each conduit that are distributedalong the horizontal length of the wellbore. The openings in theproduction conduit may be staggered laterally with respect to theopenings in the injection conduit. No packers or other flow restraints,or flow conditioners, as will be described in the case of the presentinvention, are employed to determine, or assist in the determination of,the flow distribution along the wellbore.

A single horizontal well recovery process is disclosed by Laricina intheir update of Oct. 31, 2012 to the Alberta Energy ResourcesConservation Board, and titled “Saleski Phase 1 Project Update”.Laricina describe their proposed single well recovery process asfollows: “The recovery process that has been selected is single wellcyclic SAGD process with the use of solvent technology. This processvaries the rates and compositions of solvent and steam injected over thelife of the wells. The process alternates between injectingsteam/solvent and producing water and mobile oil from the well bore. Theinjection cycle consists of injecting steam/solvent above reservoirpressure at 1,600 kPa to 5,100 kPa to heat the reservoir and reduce theviscosity of the bitumen. The reservoir is then allowed to absorb theheat from the injected steam/solvent, condense and subcool before aproduction cycle starts. The production cycle is continued until bitumenrate reaches a minimum threshold.” As described in their update,Laricina's recovery process involves variations in procedure thatincorporate Cyclic Steam Stimulation as well as SAGD, but does notinclude any management of flow along the length of a horizontal well.

The foregoing single horizontal well inventions fall into fiveapproaches to single horizontal well SAGD. The patent to Sanchez et alconstitutes one approach wherein opposing gradients are operative. Thisapproach differs profoundly from the teachings of the present invention.

The second approach, including Nzekwu and Elliot, relies on afixed-position wellbore impediment, such as a packer, to divert flowfrom the injection perforations outward into the reservoir so thatheating and chamber formation can occur. However, once heating andmobilization of oil occurs within the reservoir in the vicinity of thepacker, the opportunity for steam to flow around the packer and backinto the wellbore is provided, instead of continuing to enter thereservoir beneficially. Specifically, because of the very high virginviscosity of bitumen, the initial path of least resistance for theinjected mobilizing fluids in a single horizontal well configurationwill involve relatively shallow penetration by the mobilizing fluidsinto the reservoir, and a tendency thereafter to move longitudinallyalong the outside of the liner and thence into the production meanslocated along that same wellbore, whereupon it will enter the wellbore,and will be minimally effective or ineffective from that point onward inmobilizing bitumen within the reservoir.

The third approach, described in the paper by Marin et al., involves aproduction string that is exclusively vertical and, as such, teachesaway from the method and system of the present disclosure. The follow-uppaper by Mago et al discusses this same well, and includes simulationsof proposed steam injection configurations and methods. However, theseconfigurations and methods are fundamentally different from those of thepresent disclosure.

The fourth approach, disclosed by Kjorholt, involves horizontalinjection and production strings that traverse the wellbore, withopenings at discrete intervals along each that distribute injection andproduction respectively. However, the invention does not otherwise takesteps, or employs devices, which will alter the flow and displacementpatterns beneficially as does the present disclosure.

The fifth approach, disclosed by Laricina, includes the combination ofCyclic Steam Stimulation (CSS) and SAGD, but offers no description ofwell completion configuration, nor does it specify any associatedmethods to manage flow into the reservoir and along the wellbore as doesthe present disclosure.

Having regard to these limitations in the prior art, it is an object ofthe present disclosure to provide a single horizontal well recoveryprocess whose efficiency is enhanced by incorporating methods andsystems to mitigate the steam short-circuiting tendencies associatedwith this type of operation and, correspondingly, will extend the regionwithin the reservoir over which the viscous hydrocarbons are contactedby mobilizing fluids. The recovery process will utilize gravity drainageand for convective flow mechanisms to varying degrees, depending uponthe stage of the process, the well configuration and the reservoirproperties.

In addition to the foregoing five approaches to single horizontal wellprocesses that encompass both injection and production functions, priorsystems also include horizontal wells with injection only.

U.S. Pat. No. 8,196,661 to Trent et al, assignee Noetic TechnologiesInc., and titled “Method for Providing a Preferential Specific InjectionDistribution from a Horizontal Injection Well”, describes a concept thatinvolves an injection well only. As such, the tubing that is within thecasing has openings along its entire length so that injected fluids,such as steam, may be injected radially outward through the tubing, andthence radially outward through the casing or liner, thereby enteringthe reservoir with substantially radial flow geometry. U.S. Pat. No.8,196,661, in describing means to control the distribution of fluidsinjected radially along the length of the wellbore, makes reference todevices which provide means of increasing friction within the wellboreso as to govern the flow.

CA 2,769,044 to Butland et al, assignee Alberta Flux Solutions Ltd., andtitled “Fluid Injection Device”, describes a device or system fordistributing fluids, including steam, along an injection-only wellborewith radially outward flow into the formation. Also, it referencesdevices or approaches which modify the flow resistance within thewellbore to assist in the distribution of injected fluids.

These systems with injection only from the horizontal wellbore areconcerned with a flow geometry of only the injected fluids into thereservoir without any concern for production from the same horizontalwellbore. This requires a different flow geometry and the flow ofdifferent fluids than those required in a horizontal well with bothproduction and injection capabilities.

There is therefore a need for increasing the flow resistance of injectedfluids in a horizontal well having both injection and productioncapabilities, for the increased flow of injected fluids into thereservoir and improved production of mobilized hydrocarbons from thehorizontal well.

SUMMARY

The present disclosure is a method and system for a recovery process forrecovering hydrocarbons from a reservoir using a single horizontal wellfor both injection and production. The recovery process may utilizegravity drainage or convective flow, or both. The recovery process ispreferably a thermal or solvent recovery process. The system and processhas an injection tubing string which has openings only at or towards oneend of the horizontal well, preferably its toe end, to permit egress ofinjected fluids, and openings or perforations along the liner or outercasing of the wellbore to permit injection into the reservoir ofmobilizing fluids over a selected interval of the wellbore. Positioneddownstream therefrom along the casing or liner of that same wellbore,are openings to permit production from the reservoir of mobile andmobilized fluids.

The present disclosure minimizes or markedly reduces the shortcutting orshort-circuiting tendency of the injected fluid as it moves outward intothe reservoir along one interval of the wellbore and returns furtherdownstream into appropriate production tubulars within that samehorizontal wellbore. That is, the present system and method utilizesprocedures or equipment configurations, or combinations thereof, togovern the resistance to fluid flow of the injected fluids from the welloutward into the reservoir relative to the resistance to fluid flow ofthe injected fluids along the various tubular conduits within thewellbore. This approach results in an efficient recovery process forviscous hydrocarbons, such as bitumen, while using only a singlehorizontal well to accomplish both the injection and productionfunctions.

When implemented, the present invention allows mobilizing fluid to exitthe wellbore and enter the reservoir, and thence traverse a significantportion of the reservoir where it mobilizes viscous hydrocarbons. Theresulting mobile stream then re-enters a portion of the wellboredownstream and moves to a production means, such as a pump. To achievethis flow configuration, which permits injection and productionoperations along the same wellbore, flow gradients into and out of thereservoir must be governed while maintaining a sufficiently long openinterval that will serve as an effective production means.

In one aspect, the present disclosure provides a method of producingviscous hydrocarbons from subterranean bituminous formations, such asoil sands formations, using a single horizontal well process. The methodincludes providing a single horizontal well within the subterraneanformation wherein the horizontal well has at least one injection meansand at least one production means, spaced axially along the well andapart from the at least one injection means. Preferably the at least oneinjection means are positioned at or near the toe of the well and the atleast one injection means are positioned at or near the heel of thewell. The well may also have a casing or liner which includes openingsto the formation to allow injected fluids to flow into the formation andmobilized hydrocarbons, as well as other fluids, to flow into the wellfor production. The method also includes providing a means forsubstantially increasing resistance to axial fluid flow of mobile andmobilized fluids in the wellbore annulus, between the tubing and theliner or outer wellbore wall, along a length of the horizontal wellbetween the at least one injection means and the at least one productionmeans. A mobilizing fluid is injected through the injection means. Theinjection and production means are operated to control the ratio of theflow resistance in the wellbore annulus to the flow resistance in theformation, thereby reducing the amount of the injected mobilizing fluidthat is moving along the wellbore annulus from the injection means tothe production means and increasing the amount of the injectedmobilizing fluid entering and moving through the formation before beingdisplaced into the well to the at least one production means. Viscoushydrocarbons are produced using the production means.

Other aspects and features of the present disclosure will becomeapparent to those ordinarily skilled in the art upon review of thefollowing description of specific examples in conjunction with theaccompanying figures.

BRIEF DESCRIPTION OF DRAWINGS

The present recovery processes disclosed herein will be described withreference to the following drawings, which are illustrative and notlimiting:

FIG. 1 shows a prior art use of a horizontal well with both injectionand production means to recover hydrocarbons.

FIGS. 2 a and 2 b show horizontal wells with a constriction and/or flowconditioner along the annulus of the wellbore.

FIGS. 3 a to 3 c show examples of flow conditioners.

FIG. 4 shows a wellbore with a constriction along its length andidentifies the corresponding change in pressure gradient.

FIG. 5 is a graph showing the percent oil recovery of a method accordingto the present disclosure and conventional SAGD.

FIGS. 6 a and 6 b show a series of packers positioned in the wellbore torestrict the flow of the injected fluid.

FIGS. 7 a-7 d show four examples of the configuration for the wellcomponents using the method set out in the present disclosure.

DETAILED DESCRIPTION

The present disclosure provides a process for the recovery of viscoushydrocarbons from a subterranean reservoir using a single horizontalwell. The hydrocarbons produced using the single horizontal wellrecovery process described herein are immobile hydrocarbons or mobilehydrocarbons which benefit from a mobilizing method, such as, forexample, a thermal recovery process. That is, while the hydrocarbons mayhave some mobility, it may not be sufficient to be commerciallyeffective for production, or the mobility may be increased with athermal recovery process, or other mobilizing method, so as to improveproduction. In one aspect, the hydrocarbons are heavy oil and/orbitumen. The recovery process includes to varying degrees, dependingupon the reservoir and wellbore characteristics, gravity drainage, aswell as convective flow mechanisms. By gravity drainage is meant aprocess whose flow mechanisms are predominantly gravity controlled andwhose techniques of operation are largely oriented toward ultimatelymaximizing the influence of gravity control because of its inherentefficiency. By convective flow mechanisms is meant flow and displacementmechanisms, such as continuous or cyclic convective displacement.

In one aspect, the recovery process is a thermal or thermal and solventprocess. In such a process, steam, light hydrocarbons, hot water, orsuitable combinations thereof may be used as the injection fluid.Further, these injection fluids, such as steam and light hydrocarbons,may be injected as a mixture or as a succession or alternation offluids. Examples of light hydrocarbons include C₃ to C₁₀ hydrocarbonssuch as propane, butane and pentane.

Although the present disclosure refers to recovery processes such asthermal or solvent recovery processes, it will be understood by askilled person that the present system and method will functionbeneficially for a broad range of in situ recovery processes includingboth thermal and non-thermal processes. Examples of in situ recoveryprocesses which may be used with the present system and method and inwhich these fluid re-distribution principles may be beneficially appliedinclude those which rely, either singly or in combination, on theinjection of steam, solvents, water, surfactants, and non-condensinggases including both oxidizing and non-oxidizing gases.

The method uses a single horizontal well. In one aspect, a horizontalwell implies a well that is substantially or predominantly horizontal,but may include sections or segments that are not horizontal. The lackof horizontality over portions or segments of the well length may occuras a result of technology limitations, or may be intentional, forexample when steering the well path so that it avoids a particulargeological feature, or so that it creates a structural low point forfluid accumulation, such as a sump. This characterization of a well ashorizontal, notwithstanding possible deviations from horizontality oversegments or portions of the well length, is well known to those skilledin the art.

Further, a single horizontal well may include an individual wellborewhose openings to the reservoir have been configured to allow for bothinjection and production.

The single horizontal well may also include equipment, such as multiplestrings of tubulars, centralizers, packers, bridge plugs, sliding sealassemblies, valves, pumps, and liners which may be necessary to operatethe well in this mode. In addition, the tubulars may include features,such as slots or perforations, or other types of opening, which providemeans of egress from and ingress into those tubulars. Although referencemay be made herein to wellbores, liners, or other components of a well,these references are not limiting and will be understood by a personskilled in the art to be applicable to wellbore construction andequipment as may be appropriate for a particular reservoir.

The horizontal well used in the present recovery process includes aninjection means such as, for example, an interval along the horizontalliner which is open to injection into the reservoir of a fluid or fluidsthat are capable of mobilizing, or enhancing the mobility of, a viscoushydrocarbon, such as bitumen, upon contact. The recovery process alsoincludes a production means such as, for example, a separate intervalalong the horizontal liner which is open to production from thereservoir into the wellbore of mobile or mobilized fluids. Althoughdescribed in the singular for purposes of simplicity, there may in factbe a plurality of injection means and a plurality of production meansalong the wellbore. The injection and production means are spaced apartfrom each other along the length of the well. In one aspect, they arepositioned at or near opposite ends of the well. In an alternativeaspect, they are positioned along the length of the well at closerpositions. Their distance is determined by a number of factors includingthe reservoir characteristics, mobility of the hydrocarbons, possibilityfor short circuiting of the injected fluids from the injection means tothe production means, and the extent of recovery within the wellbore.Examples are discussed below.

In one aspect, the injection and/or production operations may becontinuous and/or simultaneous. In a further aspect, the injectionand/or production operations may proceed concurrently. In a furtheraspect, the injection and/or production operations may proceed on aninterrupted basis, including a cyclic basis. In a further one aspect,the injection and production means are isolated from each other in thewellbore. In a further aspect, the area in the formation adjacent aninjection means is absent an induced fracture.

In one aspect, the injection operation may involve the injection of asingle fluid or fluid type. In one aspect, the injection operation mayinvolve two or more fluids or fluid types. Where two or more fluids, orfluid types, are being injected, their injection may occur concurrentlyor sequentially.

In a single horizontal well operation for the recovery of a highviscosity hydrocarbons, it is necessary to mitigate the tendency ofinjected fluids to preferentially move along the wellbore annulusinstead of entering the reservoir. This entails modification of theaxial fluid resistance path, primarily within the wellbore annulus,although it can also include modification of the fluid resistance pathwithin the reservoir itself in the immediate vicinity of the wellbore.Modification of fluid resistance within the wellbore can entail theconfiguration and deployment of wellbore features and equipment, as willbe described subsequently. Modification of fluid resistance within thereservoir will inevitably occur as a result of operations that areimplemented following modifications to fluid resistance within thewellbore. In addition, however, modifications to the reservoir may beimplemented independently. For example, recovery process start-up may beaccelerated and early performance efficiency of the recovery process maybe enhanced by introducing one or more mobilizing fluids, such as steamor solvent, along a substantial portion or the entire open length of thehorizontal well.

The process for a single horizontal well is intended to ensure thatmobilizing fluids, while traversing the path of egress from the wellboreinto the reservoir via the injection means to ingress into the wellborefrom the reservoir via the production means, enter the reservoir insignificant quantities during the course of that traverse and mobilizeviscous hydrocarbons, such as bitumen. Thus, the fluid resistance withinthe wellbore is increased so that a greater percentage of the mobilizingfluid is directed or diverted into the reservoir rather than along thewellbore. In certain aspects, the present disclosure provides means ofincreasing the fluid resistance within the wellbore by using either amedium that behaves as a continuum within and along the wellbore annulusor, alternatively, an impediment or a series of discrete wellboreimpediments, including sealing elements, that are located in specificrelation to openings along the wellbore and that can be activated eitherconcurrently or sequentially, or a combination of both alternatives.Within the context of this disclosure, use of terms such as “impediment”or “sealing element” can imply a means that creates a completerestriction to flow or a partial restriction to flow.

In one aspect, the means of increasing the fluid flow resistance, namelythe primarily axial flow in the annulus of the injected fluids and ofthe mixture of mobile and mobilized fluids, traverses a length of thewellbore and engenders a variable frictional energy loss along thatlength, so that a greater percentage of the injected fluids is divertedaway from flow in the wellbore annulus and instead flows into thereservoir. The device is of substantial length compared with, forexample, the effective length of a packer, and is instrumental ininhibiting the fluid's re-entry into the wellbore from the reservoirafter traversing the reservoir for only a short distance. One example isa flow conditioner. The flow conditioner extends along the longitudinalaxis of the wellbore. It is positioned in the wellbore annulus betweenthe tubing and the liner. It may taper from one end to the otherproviding a constriction in the wellbore annulus and/or it may haveexternally extending projections that will interfere with fluid flow andprovide resistance to the flow path of a fluid in the wellbore annulus.Due to the frictional energy loss, this flow path resistance will causethe fluid to flow into the reservoir rather than through the wellboreannulus. As a result, a greater amount of injected fluid will enter thereservoir than in systems where no impediment is placed in the wellboreannulus or where only a single packer located between proximateinjection and production intervals is used as an impediment.

Because of the length of the flow conditioner, the injected fluids,along with mobile and mobilized hydrocarbons and associated reservoirfluids, will re-enter the wellbore further downstream after the flowconditioner, which therefore reduces or prevents short circuiting of theinjected fluid from the injection means to the production means of thewellbore.

In a further aspect, increasing fluid resistance in the wellboreinvolves reducing the size of the annular space between the outside ofthe tubing and the inside of the casing or liner so that fluids flowingin this reduced annular space will experience an increased resistance tofluid flow. This reduced annular space may be achieved, for example, byincreasing the diameter of the tubing, decreasing the diameter of thecasing or both. Preferably the reduced annular space is used incombination with a sealing element such as a packer positioned betweenthe injection and production means or a constriction element in theannulus which may include a sealing element that is not fully deployed.

In a further aspect, the means of increasing the flow resistance is aseries of impediments placed in the wellbore. These may be operatedconcurrently or sequentially. For example, the impediments may be aseries of sealing elements such as packers placed along the wellbore atselected distances. In one aspect, production openings are open alongthe wellbore situated in the intervening distances between the sealingelements. The sealing elements may be operated in series, with the firstset before the initial injection of fluid. Once the injected fluid shortcircuits the first sealing element, the second sealing element is set.As hydrocarbons in the reservoir are produced and the injected fluids,along with mobile and mobilized hydrocarbons and associated reservoirfluids, short circuit the sealing elements, further sealing elements areset, again forcing the injected fluids and mobile or mobilized fluids totraverse a greater portion of its flow path within the reservoir andre-enter the wellbore further downstream. Any number of sealing elementscan be used and can be set in series or concurrently, until either thedesired flow configuration is established or until physical or otherlimitations are encountered and preclude further deployment.

In one aspect, the sequential deployment of sealing elements, such aspackers, may involve the activation of successive sealing elements, eachof which is situated at a particular fixed location along the tubing,and such that the tubing itself is stationary within the well throughoutthis operation. In one aspect, one may employ as few as two packers toaccomplish a similar effect by carrying out a number of sequentialwithdrawals or re-positionings of the tubing, each time disengaging andthen re-engaging the packers in their new positions within the wellbore.In this aspect, when the tubing is re-positioned within the wellbore,the packers may remain in their current positions along the tubingstring, or may be re-positioned relative to the tubing string itself.

The staging of the sequence of packers, whether as stationary sealingelements along a stationary tubing string, or as stationary or moveablesealing elements along a tubing string that is successivelyre-positioned, as described above, may be guided by the mobility of thehydrocarbons in the vicinity of the packer. Specifically, a packer isactivated, or re-positioned and activated, at a particular locationalong the wellbore only after the hydrocarbons in the reservoircorresponding to a location immediately downstream of the packer (i.e.,between the packer and the proximal end of the horizontal well) havebecome mobile. Absent that hydrocarbon mobility, the heating fluidswhich advance in the proximal direction through the reservoir, over theinterval of wellbore occupied by the packer, may lack a means ofdisplacing the hydrocarbons into the wellbore downstream of the packer.

Alternatively, the impediments may be set simultaneously so that theflow resistance in the wellbore forces the injected fluid into thereservoir for the length of the wellbore containing the sealingelements.

In one aspect, the wellbore configuration may include constrictionswithin the wellbore, allowing some injected fluid to pass. This may beachieved in one example by partially setting the sealing elements,rather than full sealing elements. Constrictions in the wellbore mayalso be used with flow conditioners to further increase the fluid flowresistance in the wellbore. Further, the wellbore may include acombination of flow conditioners with packers or other sealing elements.

In a further aspect, the wellbore may be equipped with one or morespaced apart devices located along the length of the horizontal tubingwhich modify or impede, but do not altogether prevent, axial flow alongand within the annulus. For example, the wellbore may include a numberof spaced apart devices such as packers which may seal off the annulusat the location of those devices or fracture cups which may largelycover the cross-section of the annular area by means of frictionalcontact with the interior of the liner or casing rather than a seal.Irrespective of the particular device selected, the device may beequipped with axially oriented flow conduits, such as nozzles, one ormore of which may penetrate the device so that, notwithstanding thetendency of the device to impede or prevent axial flow, a measure offlow will occur through the axially oriented flow conduit(s) embeddedwithin that device.

In one example, injected fluids may exit the tubing near the toe of thewell and may tend to flow back along the annulus towards the heel. Aseries of spaced apart devices, such as packers or fracture cups, arelocated within the annulus, with each such device having embedded withinit one or more axially oriented nozzles. The geometry of the nozzle(s),and in particular their diameter, may be designed so that the nozzle(s)presents a major restriction to flow along the annulus, therebydiverting a major portion of the injected fluid upward or outward intothe reservoir. The nozzles' geometry may be selected so as to create theconditions for sonic (i.e., critical) flow within the nozzle. Fluidswhich pass through these nozzles may merge on the downstream side of thenozzles with fluids that had been diverted into the reservoir on theupstream side of the nozzles and which subsequently entered the annulusfrom the reservoir on the downstream side of the nozzles, bringing withthem reservoir fluids which have been mobilized. The resulting fluidmixture on the downstream side of the first set of nozzles will movetowards the second device within which one or more nozzles are embedded.Again, a portion of the fluids approaching the second set of nozzles maybe diverted into the reservoir while a portion flows through thenozzle(s) in the second device. The nozzles embedded in the seconddevice may differ in geometry and number from the nozzles embedded inthe first device. The nozzle(s) embedded in the second device may beconfigured so as to offer less resistance to fluid flow than thenozzle(s) in the first device. The nozzles in the second device may beconfigured so that flow of fluids through them is sub-critical.Additional sealing or frictional devices may be located along the lengthof the annulus with embedded nozzles.

In a further aspect, the frictional devices may be designed andconfigured so that the geometry and size of the gap or aperture betweenthe device and the surrounding casing or liner will impede or restrictflow in a specific manner, thereby acting in place of, or in additionto, embedded nozzles.

In a further aspect, the wellbore may be configured so that steam isinjected into the annulus and reservoir at a multiplicity of locations.For example, steam may be injected into two tubing strings, eachpositioned with its toe at a different location within the wellbore.Thus, in one example, steam is injected into a first tubing string whichterminates in the region of the wellbore closer to the heel, while steaminjection in a second tubing string exits the tubing closer to the toeof the well. For each such string of tubing, a series of devices asdescribed herein are placed so as to both encourage flow of injectedsteam into the reservoir and allow return of mobile and mobilized fluidsinto the wellbore for subsequent production.

The means of increasing the flow resistance in the wellbore may consistof one of the options set out herein or a combination of them. Forexample, in further aspects, the present method provides a constrictionelement and a flow conditioner; a sealing element and a flowconditioner; or a series of sealing elements acting as impedimentswithin the wellbore. These combinations provide an increase in thefrictional energy loss within the wellbore annulus. The result isredirecting more of the injected fluid into the reservoir rather thanthrough the wellbore annulus, increasing the recovery of thehydrocarbons, and improving the steam oil ratio.

In a further aspect, no openings are positioned in the wellbore betweenthe sealing elements. The casing or liner will have wall openings, orgroups of wall openings with intervening intervals containing no wallopenings. The blanked off intervals between groups of casing or lineropenings provide interior casing or liner wall locations against whichsealing elements, such as packers, may be inflated or deployed.

The design of the casing or liner in respect of the locations of itsopenings, or groups of openings, can involve considerations not only ofthe implementation of the present system and method, but also of the useof techniques employed prior to the implementation of the present systemand method to condition the near-wellbore vicinity by enhancingmobility. One such technique to enhance mobility in the near-wellboreregion involves injection of a solvent, such as xylene. An alternativetechnique for enhancing near-wellbore mobility involves a geomechanicalapproach whereby applied pressure causes a re-orientation of the sandgrains and consequent mobility improvement. A traditional technique forenhancing mobility in the near-wellbore vicinity employs heat transferprimarily by conduction and involves injecting a hot fluid, such assteam, down to the toe of the tubing and thence back around through theannulus and ultimately to the surface, the reservoir in thenear-wellbore vicinity being heated thereby as a consequence of thecirculating wellbore fluids. Such techniques, often referred to asaccelerated start-up techniques, may entail injection into the reservoirof limited fluid volumes, and may employ openings along a substantiallength of the casing or liner. Those skilled in the art will be capableof situating the groups of wall openings in the casing or liner so thatboth the step of increasing mobility in the near-wellbore vicinity andthe subsequent step of practicing the methods and systems of the presentdisclosure are accomplished.

The present method with its governance of friction in the annular regionof the wellbore as described herein permits injection and production athigh rates. This is in contrast to Nzekwu, which requires thatproduction is confined to low rates so as to avoid low pressures in thevicinity of the pump, with consequent flashing of steam, and reductionin pump efficiency. Specifically, Nzekwu requires this restriction sothat a liquid level can build in the vicinity of the pump in thevertical part of the primarily horizontal well.

FIG. 1 shows a prior system for a single horizontal well 1 in a viscoushydrocarbon reservoir. In attempting to mitigate the problem ofshort-circuiting of the injected fluid, such as steam, into and alongthe wellbore, the well 1 uses a single packer 7 placed near the distalend 5 (i.e. toe) of the well in the annular region between the tubing 2and the casing or liner 3. The packer is used as a sealing element,providing an impediment to the injected fluid. In this example, steam isinjected down the tubing 2 to the distal end 5 of the well where itexits the tubing upstream of the packer 7. There, openings in the casingor liner are provided so that the steam, prevented from movingdownstream within the annular region by the presence of the packer 7,will enter the reservoir. However, as explained above, placement of asingle packer provides only a localized and temporary mitigation of theshort-circuiting problem inasmuch as the steam, after a brief sojourn inthe reservoir, and after limited contact with and mobilization ofviscous hydrocarbons, can re-enter the wellbore through openings locatedin the casing or liner downstream of the packer, whence it will beproduced without having maximized its mobilization potential within thereservoir.

In contrast to this prior system, in the present disclosure, the processin one aspect uses a means for increasing flow resistance in thewellbore annulus to prevent or minimize short circuiting of the injectedfluid and allows it to stay in contact with the reservoir for a longerperiod of time to improve mobilization of the fluids. In another aspect,the process increases flow resistance in the wellbore annulus by usingimpediments or sealing elements, such as packers, to prevent or minimizethese short-circuiting tendencies.

FIGS. 2 a and 2 b illustrate specific aspects of the present inventionwhere, instead of a single discrete impediment to flow within thewellbore, a flow conditioner is placed in the wellbore which traverses asubstantial length of the wellbore and which engenders a variablefrictional energy loss along that length. As a result, a greaterpercentage of the injected fluids are diverted away from the wellboreand into the reservoir. FIGS. 2 a and 2 b illustrate some examples of aflow conditioner 9. As shown in FIG. 2 a, the device can be tapered toincrease the frictional resistance as the injected fluid moves towardthe impediment, i.e. the packer 7. Alternatively, as shown in FIG. 2 b,the device may be finned, with multiple ribs extending into the annulusarea to provide increased friction to the flow of the injected fluid.Flow conditioners may have a series of ribs or suitable other structurespositioned perpendicular to the longitudinal axis of the wellbore or mayhave multiple ribs extending along the longitudinal axis of thewellbore. Further, the multiple ribs may be continuous, segmented, ordivided into bristle-like formations. FIGS. 3 a to 3 c show someexamples of commercially available flow conditioners. The multiple ribsor other suitable structures along the flow conditioner interfere withthe flow of the injected fluid through the wellbore annulus between thetubing and the casing. FIG. 2B also uses a packer with the flowconditioner to further increase the flow resistance in the wellbore.Packers or other sealing elements may be used with the flow conditionersor they may be used on their own. Since the frictional energy loss isincreased, the injected fluid will be diverted into the reservoir. Thisincreases the amount of injected fluid that enters the reservoir andresults in an increase in the mobilization of hydrocarbons in thereservoir.

One or more flow conditioners may be positioned in the wellbore annulus,between the tubing and the liner, at the injection end of the casing,upstream of the packer. Alternatively or in addition thereto, one ormore flow conditioners may be positioned in the wellbore annulus on theproduction end of the wellbore downstream of the packer. FIGS. 2 a and 2b show flow conditioners 9 positioned on both the upstream anddownstream sides of the packer in the annulus in the wellbore. Byproviding the flow conditioners downstream of the packer 7, lessinjected fluid will enter the wellbore downstream on the production sidenear the packer. Instead, the injected fluid will stay in the reservoirwhere the frictional energy loss is less, and the injected fluid willenter the production side of the casing further downstream from thepacker. This reduces and/or prevents short circuiting of the injectedfluid and increases the amount of the reservoir in contact with theinjected fluid.

As shown in FIG. 4, the flow conditioners 9 are positioned within thewellbore upstream and downstream of the injection and production means.They are tapered along the longitudinal wellbore axis so that theupstream flow conditioner increases in diameter as it extends towardsthe heel of the wellbore. An adjacent flow conditioner is positioneddownstream of the upstream flow conditioner and its diameter decreasesas it extends along the longitudinal axis of the wellbore. These flowconditioners provide a constriction point in the wellbore limiting theflow of injected fluid through the annulus in the wellbore. The flowconditioners moderate the pressure drop across the constriction. Thepressure drop is higher than the pressure drop across the sand face. Asa result, the injected fluid will spread into the reservoir rather thanflow along the wellbore annulus. The injected fluid will not reenter thewellbore until the flow resistance in the wellbore decreases, becomingless than that in the reservoir, near the downstream end of thedownstream flow conditioner. This also prevents short circuiting of theinjected fluid from the injection side to the production side.

The use of flow conditioners within the wellbore may also allow for areversible recovery process without reconfiguration of the wellbore flowconditioners. For example, the injected fluid may be injected at the toeend of the wellbore initially with production of the hydrocarbons nearthe heel of the wellbore. However, in a later stage, this may bereversed and the fluid may be injected near the heel of the wellbore andproduced from the toe end of the wellbore. As shown in FIGS. 2 a and 4,the flow conditioners are positioned so that a taper occurs on both theupstream and downstream ends of the wellbore. In FIG. 2 b, the flowconditioners are present on both sides of the packer providing multipleribs or other structures which extend into the wellbore on either sideof the packer. This allows the flow conditioners to provide animpediment to the flow of the injected fluid regardless of whether it isinjected near the toe of the well with production near the heel of thewell or whether injection occurs near the heel of the wellbore withproduction near its toe. It is contemplated that the process may beinitiated in one direction and then reversed after a period ofhydrocarbon recovery has occurred.

A further example of means of increasing the flow resistance in thewellbore is shown in FIGS. 6A and 6B. These figures show a series ofsealing elements such as packers between which are openings to thereservoir at selected intervals along the length of the wellbore. Afirst packer is set as a sealing element, creating an impediment to theflow of injected fluid through the wellbore. The remaining sealingelements are not set and do not form impediments to fluid flow in thewellbore. The injected fluid will enter the wellbore, preferably at ornear the distal end, and be forced into the reservoir. As hydrocarbonrecovery occurs, the injected fluid will short circuit and re-enter thewellbore immediately downstream of the packer as shown in FIG. 6A. Toimprove hydrocarbon recovery and lengthen the time that the steam staysin the reservoir, a second packer, further along the wellbore from thefirst packer, and towards the proximal end, is now set as a sealingelement, as shown in FIG. 6B. This provides a longer length of thewellbore where the injected fluid cannot travel. As a result, the fluidwill remain in the reservoir until it reaches downstream of the secondset packer, improving hydrocarbon recovery. Once the hydrocarbonrecovery progresses and injected fluid begins to short circuit thissecond packer, a third packer will be set as a sealing element, againlimiting the section of the wellbore where the injected fluid cantravel. Any number of packers or other sealing elements can be usedalong the length of the wellbore. Although FIGS. 6A and 6B show thepackers being set in series as hydrocarbon recovery progresses, they canalso be set simultaneously. Further, although FIGS. 6A and 6B do notshow the use of flow conditioners, they may be used in conjunction withone or more of the sealing elements. For clarity, FIG. 7 shows four ofthe earlier described examples for the well components configurationusing the present method. FIG. 7A shows a system using sequentiallydeployed packers within the wellbore annulus. FIG. 7B shows a systemusing one packer and a constricted annulus. FIG. 7C shows a system usingnozzles of varying sizes within the packer/sealing elements and wherethe fluid is injected at a single point. FIG. 7D shows a system usingnozzles of varying sizes within the packer/sealing elements and wherethe fluid is injected at two points.

The above approach involving sealing elements may be modified toaccomplish the same objective but in examples involving as few as twosealing elements. In one aspect, described with respect to packers asthe sealing elements, a first packer is set, mobilizing fluids areinjected into the reservoir, those fluids eventually short circuit thefirst packer and re-enter the wellbore, whereupon a second packerfurther along the wellbore from the first packer, and directionallycloser to the heel, is deployed. However, beyond this point, instead ofdeploying successive packers, as described in the above approach, theentire assembly involving the tubing string, and the two packers, ismoved axially so that the end of the tubing is now displaced from itsoriginal position along the length of the wellbore and is locatedfurther away from the toe. In this example, subsequent engagement of thefirst and thence the second packer will allow the axial progress of theheated front from the toe towards the heel, both in the reservoir and inthe wellbore. As a further variation of this approach, when the tubingis re-located to a new position along the wellbore, it may be opportuneto actually re-position the two packers relative to the tubing stringitself. This may involve removing the tubing string from the well,re-positioning the packers relative to the toe of the tubing string, andpossibly relative to each other, and then re-installing the tubingwithin the well and positioning it at its new location.

In one aspect, the injection and production steps in the recoveryprocess of the present disclosure may entail the imposition of a higherpressure differential between injection and production means than wouldbe the case for gravity thermal recovery processes, such as SAGD. Thiswould provide a convective recovery mechanism, in addition to gravitydrainage.

The discussion herein is concentrated on a single horizontal well inisolation. The present disclosure also includes the use of laterallyadjacent single horizontal wells, with appropriate well spacing betweenthem, so that each effectively recovers viscous hydrocarbons from itsregion. Mathematical modeling has demonstrated that further efficienciescan be realized by aligning these adjacent wells appropriately. In oneexample, if two laterally adjacent wells are aligned in parallel so thatthe toe end of one well is closest to the heel end of its neighbor, thenconcurrent operation of the two wells in accordance with the principlesof this disclosure will further improve performance because of increasedvolumetric sweep efficiency, or conformance.

Further, although the above discussion refers to the injection meansbeing positioned at the toe of the horizontal well and the productionmeans positioned at the heel of the well, these positions may bereversed or altered for recovery of the hydrocarbons.

In a comparison of the present method with conventional SAGD, 800 m longwells were used. The SAGD well pairs were spaced 100 m apart while thesingle horizontal wells of the present method were spaced 50 m apart,providing the same effective spacing. Using a thin pay of 10 m,simulations were run to show the percent oil recovery. The processeswere optimized with solvent addition. The results are shown in FIG. 5.For optimization, in the single well using the present method, 5% hexanewas added for 1 year while in the SAGD process, 1.5% hexane was addedfor 1 year. While these amounts of hexane differ, they representequivalent amounts of injected hexane using the two processes. Theexample using the single well in the present method injects only at thetoe end of the well while the SAGD process injects along the length ofthe well. As a result, the higher concentration of the injected hexanein the single well example is an equivalent amount as compared to thelower concentration of the injected hexane in the SAGD example. Thegraph shows that the present method provides for an increased oilrecovery over time as compared to a conventional SAGD process. Recoverycan be further improved by using accelerated start up process, examplesof which are known in the art.

The methods and systems described in this disclosure are intended to becapable of operating independently of any adjacent or neighboring wellsor well groups. As such, the methods and systems of the presentdisclosure are applicable in a virgin reservoir. However, it will bereadily understood by those skilled in the art that single wells may bestrategically located, and single well recovery processes may beoperated within a reservoir to harvest hydrocarbons which have been orwould otherwise be bypassed by nearby or surrounding in situ recoveryoperations. Wells employed in this capacity are sometimes referred to asinfill wells. The methods and systems of the present disclosure may beused in that capacity.

Reference is made to exemplary aspects and specific language is usedherein. It will nevertheless be understood that no limitation of thescope of the disclosure is intended. Alterations and furthermodifications of the features described herein, and additionalapplications of the principles described herein, which would occur toone skilled in the relevant art and having possession of thisdisclosure, are to be considered within the scope of this disclosure.Further, the terminology used herein is used for the purpose ofdescribing particular aspects only and is not intended to be limiting,as the scope of the disclosure will be defined by the appended claimsand equivalents thereof. All publications, patents, and patentapplications mentioned in this specification are herein incorporated byreference to the same extent as if each individual publication, patentor patent application were each specifically and individually indicatedto be incorporated by reference.

What is claimed is:
 1. A method of producing viscous hydrocarbons from asubterranean formation, comprising: providing a single horizontal wellwithin the subterranean formation wherein the horizontal well comprisesan outer wall, at least one injector for injecting a mobilizing fluidinto the reservoir, the at least one injector comprising a conduitwithin the well to inject the mobilizing fluid to the distal end of theconduit, an annulus extending along the longitudinal axis of the well,and at least one producing component, positioned apart from the at leastone injector, for producing hydrocarbons from the reservoir; providing,within the annulus, a flow conditioner for substantially increasingaxial fluid flow resistance within the annulus along a length of thehorizontal well between the at least one injector and the at least oneproducing component; injecting the mobilizing fluid through the at leastone injector; operating the at least one injector and the at least oneproducing component to control the ratio of the flow resistance in thewell to the flow resistance in the formation, thereby reducing theamount of the injected mobilizing fluid moving through the annulus fromthe at least one injector to the at least one producing component andincreasing the amount of the injected mobilizing fluid entering andmoving through the formation before being displaced into the well to theat least one producing component; and producing viscous hydrocarbonsthrough the at least one producing component.
 2. The method of claim 1wherein the method uses: a gravity-dominated fluid flow or displacementmechanism to recover the viscous hydrocarbons; a convectively dominatedfluid flow or displacement mechanism to recover the viscoushydrocarbons; or a combination of convective and gravity fluid flow anddisplacement mechanisms to recover the viscous hydrocarbons.
 3. Themethod of claim 1 wherein the flow conditioner for increasing fluid flowresistance provides a constriction in the annulus to increase the fluidflow resistance of the injected mobilizing fluid as the fluid re-entersthe annulus from the reservoir.
 4. The method of claim 1 wherein theflow conditioner for increasing fluid flow resistance is selected fromthe group consisting of: one or more flow constrictors positioned in theannulus; one or more partial sealing elements positioned in the annulus;and two or more sealing elements positioned in the annulus of the wellbetween the at least one injector and the at least one producingcomponent.
 5. The method of claim 4 wherein the one or more flowconstrictors extend along a portion of the length of the annulus betweenthe injector and the producing component.
 6. The method of claim 4wherein the two or more sealing elements are operated in series orsimultaneously.
 7. The method of claim 4 further comprising operatingthe two or more sealing elements in a staged manner by activatingsealing elements in a staged manner in a direction from the at least oneinjector to the at least one producing component.
 8. The method of claim4 wherein, following an initial activation of the two or more sealingelements, the sealing elements are deactivated, moved longitudinallythrough the annulus and reactivated in a new position relative to the atleast one injector portion and the at least one producing component. 9.The method of claim 4 wherein prior to one of the sealing elements beingactivated, the viscous hydrocarbons in the formation immediatelydownstream of the one of the sealing elements are sufficiently mobile toundergo displacement by the injected mobilizing fluid once the one ofthe sealing elements has been activated.
 10. The method of claim 4wherein, in the interval(s) between the two or more sealing elements,the outer wall of the well, contains openings, or groups of openings, toallow hydraulic communication between the well and the formation. 11.The method of claim 4 wherein the portion of the outer wall of the wellbetween the two or more sealing elements does not have openings into thereservoir.
 12. The method of claim 4, wherein the one or more partialsealing elements comprises a sealing element with one or more flowconduits extending through the sealing element for allowing a desiredflow of the mobilizing fluid.
 13. The method of claim 12 wherein the oneor more partial sealing elements comprises more than one sealing elementwith one or more flow conduits extending through each of the more thanone sealing element, wherein the flow conduits in each sealing elementallow for a different mobilizing fluid flow rate than the fluid flowrate in at least one other of the sealing elements.
 14. The method ofclaim 12 where the flow velocity in one or more of the flow conduits issonic flow and critical flow.
 15. The method of claim 1 wherein the stepof producing the viscous hydrocarbons comprises pumping the hydrocarbonsto the surface without maintaining a substantial liquid level in thehorizontal well.
 16. The method of claim 1 wherein the viscoushydrocarbons are selected from the group consisting of bitumen, heavyoil, and unmobilized hydrocarbons.
 17. The method of claim 1 wherein theinjected fluid comprises steam, hot water, light hydrocarbons, ormixtures thereof or one or more of non-condensing gases and surfactants.18. The method of claim 1 wherein: the injector injects fluids at ornear a toe of the horizontal well and the producing component producesviscous hydrocarbons at or near a heel of the horizontal well; or theinjector injects fluids at or near a heel of the well and the producingcomponent produces the viscous hydrocarbons at or near a toe of thewell.
 19. The method of claim 1 wherein the at least one injectorincludes two injector, each injector injecting the mobilizing fluid at adifferent section in the well and each of the two injector having flowconditioners for substantially increasing axial fluid flow resistancewithin the annulus along the length of the horizontal well.
 20. Themethod of claim 1 wherein a plurality of single horizontal wells isemployed.